1. Technical Field
The present invention relates in general to a method for detecting stress corrosion cracking in steel gas pipelines, and in particular to a method for predicting with a high degree of accuracy the presence at a specific location of stress corrosion cracking in such pipelines.
2. Description of the Prior Art
Since the early 1960's pipe manufacturers have developed high strength steels for pipeline applications in order to reduce the pipe wall thickness required to achieve maximum allowable operating pressures specified by pipeline operators. These higher strength steels have higher tensile or residual stresses and in combination with applied stresses (hoop stresses from pressure generated by compressing natural gas for transportation) increase the potential for stress corrosion cracking (SCC) to occur.
In-line inspection tools or instrumented tools also known as intelligent or smart tools contain various sensors, sophisticated electronics, onboard computers and recording devices that collect data which is later analyzed by a specialist using special software to reveal information about the condition of the pipeline. Technology has been commercially developed and applied to detect pipe body wall metal loss and crack-like features. Unfortunately, the most useful signature from these tools has been ignored. Low level analysis for metal loss has not been used to indicate disbanded coating in conjunction with topography and SCC indications. This methodology is critical to determining where SCC really exists and for prevention of very costly exploratory digs on high-pressure pipeline systems. These are different types of technology with the in-line inspection smart tools run separately to collect the metal loss or crack feature data.
The principles of magnetic flux leakage technology are predominantly used to detect pipe body wall loss in gas pipelines. When the pipe is magnetized to an optimum inspection level and no defects exist, all lines of magnetic flux will be contained within the pipe wall. If defects exist, the lines of magnetic flux will be redistributed around the defect. The result will be that some of the lines of magnetic flux will ‘leak’ out into the surrounding medium. A magnetic field sensor, scanning along the surface of the pipe wall will detect any leakage field and output an electrical signal proportional to the defect's depth and shape. Originally, analog smart tools were developed using flux leakage technology in the 1960's and presently these tools are being converted to digital technology. Trained analysts review the processed data in a visual computer format to review and interpret the inspection data and grade the metal loss severity. In-line inspection metal loss smart tool vendors typically report the metal loss depth from 15% or greater depth penetration allowing for pipe manufacturing mill tolerance variances. Surveys can be graded at a specific depth more or less than 15% if requested by the operating company and if feasible for the vendor to interpret data results.
The principles of ultrasonic technology have been used successfully by commercial smart tool vendors for many years to find crack-like features in pipeline steels. Ultrasonic waves, such as elastic waves or electromagnetic acoustic waves, are transmitted via transducers into the pipe wall. These waves are reflected when they encounter discontinuities such as cracks and a portion of their energy is reflected back as an ultrasonic signal. The signal is then processed and recorded for later analysis. A serious problem with using ultrasonic technology for finding crack-like features is the inability to adequately distinguish a crack-like feature to non-critical reflector features such as manufacturing inclusions or mechanical scratches on the pipe surface as a result of construction or manufacturing practices. As many as 50% of the crack-like features reported from the smart tool can be attributed to mechanical or metallurgical defects rather than SCC. Interpretation analysts using specially developed computer software grade the survey and prepare the survey report.
Soil characterization and modeling is a tool which predicts SCC susceptibility based on a database of soil characteristics and then combining that information with the physical pipeline characteristics such as steel grade, age, coating type and condition, operating pressure, etc. The soil characterization survey is performed by walking the length of the pipeline segment and periodically collecting a soil sample from pipeline depth with a hand auger. The soil type is determined along with the associated drainage and topography. The bottom soil sample collected at pipeline depth can be tested for pH and presence of carbonate substances and other chemicals known to be present where SCC has been found on pipelines. All data collected is then associated with the pipeline footage/chainage survey. This data is then combined with the pipeline physical characteristics into a specialized computer model to predict the possibility of SCC being present assuming the coating is disbonded allowing the environment to make contact with the pipe wall at the pipeline footage/chainage location.
A hydrostatic test is a method of confirming pipeline integrity by pressuring the pipeline up to a defined pressure above the operating pressure using a liquid medium such as water. For a gas pipeline, it involves removing the pipeline from gas service, installing special test manifolds, filling and pressurizing the pipe using a liquid medium. This technique will find SCC features that will not sustain the achieved pressure, but will not find or identify the location of any sub-critical crack-like features.
Historically, gas pipeline operators have relied on periodically pressure testing pipelines to confirm integrity as a method of finding SCC. Some operators have also run in-line inspection SCC smart tools to identify where the cracks could be located. Unfortunately, numerous excavations have to be performed where mechanical or metallurgical false reflector indications are found rather than SCC. Other operators have used the soil characterization and SCC model surveys to perform excavations to investigate whether SCC is present. The soil characterization survey does not provide a survey that definitively confirms SCC but indicates the possible presence if the coating is disbanded and the environment has come into contact with the pipeline for a sustained period of time to promote crack growth.
Stress corrosion cracking is a form of environmentally assisted cracking where the surrounding environment, pipe material and stress act together to reduce the strength or load carrying capacity of the pipeline. It is the result of a chemistry and a physics problem working together, and the mechanism is electrochemical-mechanical. When steel comes into contact with water, the minerals and gases in the water at the pipe surface create cells that attack the steel. This chemical or electrochemical reaction is corrosion and, in other situations, would typically create general pipe wall thinning or pits in the steel. In SCC, stress and corrosion work together to weaken the pipe. Ultimately, the cracks continue to develop in depth and width or merge together with adjacent cracks to make a single longer crack to the point that the crack location is weakened beyond the stress load and thus mechanical failure occurs.
Research into the process of near neutral/low pH stress corrosion cracking has only been initiated in the last fifteen years or so since the first pipeline failure occurred that was attributed to this type of SCC. The scientific research community generally agrees that the following processes are required for near neutral or low pH SCC to develop.
Three conditions are necessary and must be present for stress corrosion cracking to occur: 1) a chemical environment that initiates a crack at the pipeline wall surface; 2) a susceptible steel pipe material, and 3) tensile stress in the pipeline steel. If any one of these three conditions listed above could be eliminated or reduced to a point where cracking would not occur, then SCC could be prevented.
Cracks are most likely initiated at pits on the steel surface of the pipeline where a localized environment is generated that has a pH low enough to produce atomic hydrogen in the pit. The presence of carbon dioxide in the groundwater assists in creating near neutral pH levels. Some of the discharged atomic hydrogen enters the steel, degrading the mechanical properties locally so that the cracks are initiated or grown by a combination of dissolution and hydrogen embrittlement. Continued anodic dissolution in the crack is necessary for crack growth, assisted by hydrogen entry into the steel. The plastic stress level necessary to produce cracking may not be related solely to fracturing the embrittled steel. It may also contribute by rupturing the protective film, allowing hydrogen to reach and then penetrate the steel. The cracks generated by near neutral/low pH SCC are generally transgranular where the cracks follow a path across or through the grains.
Near neutral/low pH stress corrosion cracking is associated with shallow external corrosion pitting. Internal in-line inspection smart tools are commercially available that detect external corrosion pitting. The environment for near neutral/low pH SCC can only develop after damage to or disbondment of the pipe coating and in the absence of the cathodic protection current used to control external pipeline corrosion. Some types of pipeline coatings when disbanded act as a barrier shielding cathodic protection from reaching the pipe surface.
The Canadian National Energy Board held an inquiry and subsequently published a Report of the Inquiry titled Stress Corrosion Cracking on Canadian Oil and Gas Pipelines in November 1996. Following that report the Canadian Energy Pipeline Association (CEPA) published Stress Corrosion Cracking Recommended Practices in May 1997. These documents discuss the processes described above (in-line metal loss and SCC smart tools, soil characterization and modeling) as separate technologies. The CEPA SCC Recommended Practices consist of a compilation of guidelines based on practices at the time of publication to support companies in the management of their longitudinal, low-pH SCC concerns. In April 1995, the Gas Research Institute published a report for member companies titled Stress Corrosion Cracks in Pipelines: Characteristics and Detection Considerations. This report presents an overview of stress corrosion cracking in pipelines with a particular emphasis on aspects that are relevant to the development of in-line inspection tools and interpretation of inspection signals. Numerous other research articles on near neutral/low pH SCC mechanics have been written and published by the National Association of Corrosion Engineers.
There are many disadvantages associated with the traditional SCC detection methods for near neutral/low pH stress corrosion cracking on steel gas pipelines. The traditional SCC detection methods include using separately 1) in-line pipeline inspection data obtained with smart tools that are designed to detect external pipeline wall crack-like features; 2) in-line smart tool inspection for external metal loss corrosion anomalies; or 3) soil characterization surveys having computerized data modeling to determine susceptible terrain for SCC.
One disadvantage is that the traditional near neutral/low pH SCC detection methods yield false or inconclusive results. Moreover, the methods to confirm the location of SCC in a pipeline are costly and highly labor-intensive. Heretofore, such pipelines in which SCC was suspected were taken out of gas transmission service, and subjected to hydrostatic testing.
Another disadvantage is that the results of the traditional SCC detection methods have not been integrated and comparatively evaluated to determine with high confidence whether actual SCC exists at a physical gas pipeline location. A key component not used before this invention was to utilize low level analysis of metal loss in-line inspection tool surveys rather than conventional grading methodology. Heretofore, such detection results were evaluated separately.
Accordingly, prior to the development of the present invention, there has not been a method of integrating in-line pipeline wall inspection results, in-line low level external metal loss external corrosion analysis results and soil characterization model results to determine with high confidence whether actual SCC exists at a physical gas pipeline segment location. Therefore, the art has sought a low cost and reliable method of integrating such methods to confirm and/or predict the location of segment of a steel gas pipeline that is susceptible to SCC.